Multiple distributed pressure measurements

ABSTRACT

Methods, computer programs, and systems for detecting at least one downhole condition are disclosed. Pressures are measured at a plurality of locations along the drillstring. The drillstring includes a drillpipe. At least one of the pressures is measured along the drillpipe. At least one downhole condition is detected based, at least in part, on at least one measured pressure.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. patent application Ser. No.11/051,762, filed Feb. 4, 2005, entitled “Multiple Distributed PressureMeasurements,” by Daniel Gleitman, which, in turn, claims priority tocommonly owned U.S. provisional patent application Ser. No. 60/550,033,filed Mar. 4, 2004, entitled “Multiple Distributed Sensors Along ADrillpipe,” by Daniel Gleitman.

BACKGROUND

As oil well drilling becomes increasingly complex, the importance ofcollecting downhole data while drilling increases.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a system for processing downhole data.

FIG. 2 illustrates a portion of drillpipe with an affixed sensor and acommunications medium.

FIG. 3 illustrates a portion of drillpipe with a sensor-modulereceptacle.

FIG. 4 illustrates a portion of drillpipe with a pressure sensor in asensor-module receptacle.

FIG. 5 illustrates drillpipe joints and a gasket.

FIG. 6 is a cut-away diagram of the pin-end of a drillpipe joint withpressure sensors affixed to the joint.

FIG. 7 is a cut-away diagram of a node sub with a pressure sensor.

FIG. 8 shows a block diagram for a pressure sensor.

FIG. 9 shows a block diagram of a drillpipe coupler.

FIGS. 10 and 11 illustrate connectors for sensor couplers and drillpipecouplers.

FIG. 12 shows a block diagram of a system for detecting at least onedownhole condition.

FIG. 13 illustrates a borehole.

FIGS. 14 and 15 illustrate pressure-versus-depth plots of a set of data.

FIG. 16 shows a block diagram of a system for detecting at least onedownhole condition.

FIG. 17 shows a block diagram of a system for identifying, locating, andcharacterizing at least one downhole condition.

FIG. 18 shows a block diagram of a system for identifying and locating adownhole condition.

FIGS. 19-21 illustrate pressures versus depth for value sets.

FIG. 22 shows a block diagram of a system for identifying and locating adownhole condition.

FIGS. 23-24 illustrate pressures versus depth for value sets.

FIG. 25 shows a block diagram of a system for identifying and locating adownhole condition.

FIG. 26 illustrates pressures versus depth for value sets.

FIG. 27 shows a block diagram of a system for identifying and locating adownhole condition.

FIGS. 28-29 illustrate pressures versus depth for value sets.

FIG. 30 shows a block diagram of a system for identifying and locating adownhole condition.

FIGS. 31-32 illustrate pressures versus depth for value sets.

FIG. 33 show a block diagram of a system for identifying and locatingadditional downhole conditions.

FIGS. 34-35 show block diagrams of systems for additional action basedon detected conditions.

FIG. 36 shows a block diagram of a system for modifying an expectedvalue set.

DETAILED DESCRIPTION

As shown in FIG. 1, oil well drilling equipment 100 (simplified for easeof understanding) includes a derrick 105, derrick floor 110, draw works115 (schematically represented by the drilling line and the travelingblock), hook 120, swivel 125, kelly joint 130, rotary table 135,drillpipe 140, one or more drill collars 145, one or more MWD/LWD tools150, one or more subs 155, and drill bit 160. Drilling fluid is injectedby a mud pump 190 into the swivel 125 by a drilling fluid supply line195, which may include a standpipe 196 and kelly hose 197. The drillingfluid travels through the kelly joint 130, drillpipe 140, drill collars145, and subs 155, and exits through jets or nozzles in the drill bit160. The drilling fluid then flows up the annulus between the drillpipe140 and the wall of the borehole 165. One or more portions of borehole165 may comprise open hole and one or more portions of borehole 165 maybe cased. The drillpipe 140 may be comprised of multiple drillpipejoints and may optionally include one or more subs 155 distributed amongthe drillpipe joints. If one or more subs 155 are included, one or moreof the subs 155 may include sensing equipment (e.g., sensors),communications equipment, data-processing equipment, or other equipment.The drillpipe joints may be of any suitable dimensions (e.g., 30 footlength). A drilling fluid return line 170 returns drilling fluid fromthe borehole 165 and circulates it to a drilling fluid pit (not shown)and then the drilling fluid is ultimately recirculated via the mud pump190 back to the drilling fluid supply line 195. The combination of thedrill collar 145, MWD/LWD tools 150, and drill bit 160 is known as abottomhole assembly (or “BHA”). The combination of the BHA, thedrillpipe 140, and any included subs 155, is known as the drillstring.In rotary drilling the rotary table 135 may rotate the drillstring, oralternatively the drillstring may be rotated via a top drive assembly.

The terms “couple” or “couples,” as used herein are intended to meaneither an indirect or direct connection. Thus, if a first device couplesto a second device, that connection may be through a direct connection,or through an indirect electrical connection via other devices andconnections. The term “upstream” as used herein means along a flow pathtowards the source of the flow, and the term “downstream” as used hereinmeans along a flow path away from the source of the flow.

It will be understood that the term “oil well drilling equipment” or“oil well drilling system” is not intended to limit the use of theequipment and processes described with those terms to drilling an oilwell. The terms also encompass drilling natural gas wells or hydrocarbonwells in general. Further, such wells can be used for production,monitoring, or injection in relation to the recovery of hydrocarbons orother materials from the subsurface.

One or more pressure sensors 175 may be distributed along the drillpipe,with the distribution depending on the needs of the system. One or moresuch pressure sensors 175 may be used to measure pressure along thedrillpipe. In an example implementation, one or more pressure sensors175 are located on or within the drillpipe 140. Other pressure sensors175 may be on or within the drill collar 145 or the one or more MWD/LWDtools 150. Still other pressure sensors 175 may be in built into, orotherwise coupled to, the bit 160. Still other pressure sensor 175 maybe disposed on or within one or more subs 155.

Other pressure sensors 175 may be located at or near the surface tomeasure, for example, one or more of drilling fluid supply line (e.g.standpipe) or return line pressures. In many cases a pressure sensor 175located on or along the standpipe 196 (or other drilling fluid supplyline location) may be used to provide drillstring interior pressuremeasurements at or near the top of the drillstring or borehole. Incertain example implementations, the drillstring interior pressure maybe determined inferentially based on pressure measurements, using, forexample, pressure measurements taken from the drilling fluid supplyline. In some example implementations, a pressure sensor 175 located onor along a return line may be used to provide drillstring exterior orannulus pressure measurements at or near the top of the drillstring orborehole. In some example systems, drillstring exterior or annuluspressure measurements at or near the top of the drillstring or boreholemay be determined inferentially, using, for example, pressuremeasurements taken on a return line. In some example systems,drillstring exterior pressure at the top of the drillstring or boreholemay be determined inferentially based on atmospheric pressure. Stillother pressure sensors 175 may be affixed to one or more locations alongthe borehole 165. Other pressure sensors 175 may be circulated in thedrilling fluid.

In certain implementations, one or more pressure sensors 175 may beported (e.g., hydraulically ported) to the outside of one or moreportions of the drillstring, such as the drillpipe 140, the drill collar145, the MWD/LWD tools 150, the subs 155, or the bit 160. The pressuresensors 175 ported to the outside of the drillstring may measure one ormore pressures in an annulus defined by the drillstring and the borehole165. In certain example implementations, one or more pressure sensors175 may be ported to the interior of the drillstring and may measure thepressure within the drillstring. In certain implementations, one or morepressure sensors 175 may be ported to the exterior of the drillstring tomeasure one or more pressures in the annulus and one or more otherpressure sensors 175 may be ported to the interior of the drillstring tomeasure one or more pressures within the drillstring. Pressure sensors175 may be ported to the interior or exterior of drillstring elements toobtain static pressure measurements.

In certain implementations, one or more pressure sensors 175 may beported to drillstring components that are used for drilling and that aresubsequently left in the borehole 165. These drillstring components maybe used in casing-while-drilling (i.e. drilling with casing) operations.The drillstring components may be included in a completed well. In suchan implementations, one or more pressure sensors may measure and reportpressure after drilling operations are complete.

The pressure sensors 175 convert pressures to one or more signals. Oneor more pressure sensors 175 may include strain gauge type devices,quartz crystal devices, fiber optical devices, or other devices used insensing pressure. The one or more signals from the pressure sensors 175may be analog or digital. In certain implementations, one or morepressure sensors 175 may be oriented to measure one or more staticpressures. For example, one or more pressure sensors 175 may be orientedperpendicular to streamlines of the drilling fluid flow. One or morepressure sensors 175 may measure stagnation pressure by orienting thepressure sensors 175 to face, or partially face, into the drilling fluidflow. In certain implementations, one or more pressure sensors 175 mayuse an extended pitot tube approach or a shallow ramping port to orientthe sensors 175 to face, or partially face, into the drilling fluidflow. The measurement accuracy of the stagnation pressure may varydepending on a degree of boundary layer influence.

A portion of drillpipe 140 is schematically illustrated in FIG. 2. Theillustrated portion of drillpipe includes interfaces 210 between thejoints that form drillpipe 140. Interfaces 210 may include threadedmechanical connections which may have different inner and outerdiameters as compared to the balance of the drillpipe. One or more ofthe interfaces 210 may include communication interfaces. Signals frompressure sensors 175 are coupled to communications medium 205, which maybe disposed in the drillpipe 140 or external to the drillpipe 140.Drillpipe, such as drillpipe 140, with communications medium 205, maycollectively be referred to as a wired drillpipe.

In one example system, the communications medium 205 may be locatedwithin an inner annulus of the drillpipe 140. The communications medium205 may comprise one or more concentric layers of a conductor and aninsulator disposed within the drillstring. In another example system,the drillpipe 140 may have a gun-drilled channel though at leastportions of its length. In such a drillpipe 140, the communicationsmedium 205 may be placed in the gun-drilled channel. In another examplesystem, the communications medium 205 may be fully or partly locatedwithin a protective housing, such as a capillary tubing that runs atleast a portion of the length of the drillpipe 140. The protectivehousing may be attached or biased to the drillpipe inner diameter orstabilized within the drillpipe bore.

The communications medium 205 may be a wire, a cable, a fluid, a fiber,or any other medium. In certain implementations, the communicationsmedium may permit high data transfer rates. The communications medium205 may include one or more communications paths. For example, onecommunications path may connect to one or more pressure sensors 175,while another communications path may connect another one or more sensorsensors 175. The communications medium 205 may extend from the drillpipe140 to the subs 155, drill collar 145, MWD/LWD tools 150, and the bit160. The communications medium 205 may include physical connectors ormating conductors to complete a transition in the communications medium205 across drillpipe joints and other connections.

The communications medium 205 may transition from one type to anotheralong the drillstring. For example, one or more portions of thecommunications medium 205 may include an LWD system communications bus.One more or portions of the communications medium 205 may comprise a“short-hop” electromagnetic link or an acoustical telemetry link. The“short-hop” electromagnetic links or acoustical telemetry link may beused to interface between drillpipe joints or across difficult-to-wiredrillstring components such as mud motors.

A processor 180 may be used to collect and analyze data from one or morepressure sensors 175 This processor 180 may process the pressure dataand provide an output that is a function of the processed or unprocessedpressure data. This output may then be used in the drilling process. Theprocessor may include one or more processing units that operate together(e.g., symmetrically or in parallel) or one or more processing unitsthat operate separately. The processing units may be in the samelocation or in distributed locations. The processor 180 mayalternatively be located below the surface, for example, within thedrillstring. The processor 180 may operate at a speed that is sufficientto be useful in the drilling process. The processor 180 may include orinterface with a terminal 185. The terminal 185 may allow an operator tointeract with the processor 180.

The communications medium 205 may transition to connect the drillstringto the processor 180. The transition may include a mechanical contactwhich may include a rotary brush electrical connection. The transitionmay include a non-contact link which may include an inductive couple ora short-hop electromagnetic link.

The pressure sensors 175 may communicate with the processor 180 throughthe communications medium 205. Communications over the communicationsmedium 205 can be in the form of network communications, using, forexample, Ethernet. Each of the pressure sensors 175 may be addressableindividually or in one or more groups. Alternatively, communications canbe point-to-point. Whatever form it takes, the communications medium 205may provide high-speed data communication between the sensors in theborehole 165 and the processor 180. The speed and bandwidthcharacteristics of the communications medium 205 may allow the processor180 to perform collection and analysis of data from the pressure sensors175 fast enough for use in the drilling process. This data collectionand analysis may be referred to as “real-time” processing. Therefore, asused herein, the term “real-time” means a speed that is useful in thedrilling process.

A portion of drillpipe 140, including a sensor-module receptacle 310 isillustrated in FIG. 3. The sensor-module receptacle 310 is defined by arecess in the exterior of the drillpipe 140. The recess may be in theexterior of an upset drillpipe joint. The sensor-module receptacle 310may be any suitable size or shape to engage and retain a pressure sensor175. The sensor-module receptacle 310 may also include threads to retainthe pressure sensor 175 within sensor-module receptacle 310. Thedrillpipe 140 may also include one or more drillpipe couplers, such asdrillpipe coupler 315, to couple the signal from the sensor in pressuresensor 175 to the communications medium 205. When the sensor-modulereceptacle 310 is empty, a sensor-module-receptacle cover 320 may beused to cover the sensor-module receptacle 310. An examplesensor-module-receptacle cover 320 may have an exterior for plugginginto the sensor-module receptacle 310. Another example pressuresensor-receptacle cover 320, for use with a sensor-module receptacle 310that is threaded, is shaped such to engage the threading when place onsensor-module receptacle 310.

A portion of drillpipe 140, including a pressure sensor 175 insensor-module receptacle 310 is illustrated in FIG. 4. The pressuresensor 175 may be any suitable size and shape to plug into thesensor-module receptacle 310. If the sensor-module receptacle 310includes threading, the exterior pressure sensor 175 may havecomplementary features, such as threading, to engage the sensor-modulereceptacle 310 threading. The pressure sensor 175 may have a protectiveexterior to isolate it from the ambient conditions exterior to thedrillpipe 140 which may include the mud flowing around drillpipe 140.The pressure sensor 175 may be easily inserted and removed fromsensor-module receptacle 310 to permit swapping or replacement ofpressure sensors 175, based on the type of data to be collected in theportion of the drillpipe 140 where the pressure sensor 175 will belocated, or for maintenance.

In addition to sensor-module receptacles 310, pressure sensors 175 mayalso be mounted on gaskets between joints of drillpipe. Two joints ofdrillpipe 505 and 510 with a gasket 515 are schematically illustrated inFIG. 5. Each of the joints of drillpipe 505 and 510 have a pin end 520and a box end 525. Both the pin and box ends may include threading andload shoulders to allow forming the drillpipe 140 from the joints. Agasket 515 may be placed between the load shoulder of box end 520 ofdrillpipe joint 505 and the load shoulder of pin end 515 of drillpipejoint 510. When the two joints 505 and 510 are joined together, thegasket is located at the interface between the joints. A pressure sensor175 may be incorporated within gasket 515 or may be mounted to theexterior of gasket 515. The output of the sensor in the pressure sensor175 may be coupled to the communications medium 205 using one or more ofthe methods described below with respect to FIG. 10. This arrangementallows the mounting of pressure sensors on drillpipe without sensorreceptacles in the drillpipe 140. The gasket-mounted pressure sensorsmay be used alone, or in conjunction with pressure sensors mounted asdescribed with respect to FIGS. 2 and 3. In another embodiment, apressure sensor receptacle 310 may be created in the exterior of thegasket 515.

In addition to sensor-module receptacles 310 and gaskets 515, pressuresensors 175 may also be mounted in the ends of drillpipe joints. Across-sectional diagram of the box end 605 of a drillpipe joint is shownin FIG. 6. The joint of drillpipe includes a box end 605 adapted toretain a box-end insert 610. The box end 605 may include an elongatedupset portion. The interior of the box end 605 of the joint may be boredback (beyond the threads) to allow the box-end insert 610 to be placedin the bored-back area. The box-end insert 610 may include one or morepressure sensors 175. The pressure sensors 175 may be ported to measureone or more of bore pressure or annular pressure exterior to thedrillpipe joint. For example, one or more pressures sensors 175 mountedin the box-end insert 610 may be coupled with a conduit 615 to theexterior of the drillpipe joint. The conduit 615 may include one or moredrilled holes, one or more capillary tubes, one or more seals, or othermeans to port the annular pressure to a pressure sensor disposed withinthe drillpipe joint. In general, one or more pressure sensors 175 may beported to measure bore or internal pressure. The box-end insert 610 mayinclude one or more communication couplers, such as drillpipe coupler315. The box-end insert 610 may include other communication orprocessing equipment.

A cross-sectional diagram of an example sub 155 is shown in FIG. 7. Thesub 155 shown in FIG. 7 may include threading to attach between twodrillpipe joints. One or more portions of the sub 155 may be cut away toform pressure sensor receptacles 310 to contain pressure sensors 175.The sub 155 may include a coupler 315 to couple the pressure sensor 175to the communications medium 205. The box-end of the sub 155 may bebored back to retain a box-end insert 610. The box-end insert 610 mayinclude one or more pressure sensors 175 ported to measure annularpressure. The box-end insert 610 may include one or more pressuresensors 175 ported to measure bore pressure. The box-end insert mayinclude one or more communications couplers, such as drillpipe coupler315. The communications medium may be disposed in the sub 155. Asdiscussed above, the sub 155 may include communication equipment.

An example pressure sensor 175, shown schematically in FIG. 8, includesa sensor device 805 to produce a signal indicative of the pressure itexperiences. The sensor device 805 may be positioned within the pressuresensor 175 so that the sensor device 805 is ported or protrudes from thepressure sensor 175, allowing the sensor device 805 to directly measurea fluid pressure external to the pressure sensor 175. In each of thepressure sensor types discussed, suitable porting via drilled holes,capillary tubes, seals, or other means may be employed to port the fluidat the desired pressure measurement location (e.g. within or external todrillstring), into the pressure sensor.

The output from the sensor device 805 may be digital or analog.Depending on the mode of communications used over the communicationsmedium 205, the output from the sensor may require conversion fromanalog to digital with an analog-to-digital converter 810. The pressuresensor 175 may also include a plurality of analog-to-digital converters810 to accommodate multiple sensors 805. After the sensor device 805 hasproduced a signal indicative of the measured property, the signal willbe coupled to the communication medium 205 using a communicationscoupler, which may include a sensor coupler 815 within the pressuresensor 175 and may include a drillpipe coupler 315 (shown in FIG. 3).The sensor coupler may include a connector 820 for inducing a signal inthe drillpipe coupler 315, shown in FIG. 9. The drillpipe coupler mayinclude a connector 905 for engaging the sensor coupler connector 820.Connectors may include direct electrical connection and example suitableconnectors of this type include those from Kemlon and Greene Tweed, bothof Houston, Tex.

The communication coupler, which is the combination of the sensorcoupler 815 and the drillpipe coupler 315, performs signaltransformations necessary to couple the sensor signal to thecommunications medium 205. One example communication coupler mayre-encode the signal from the sensor device 805 or the analog-to-digitalconverter, include header information, and transmit the signal over thecommunication medium 205.

An example complementary pair of sensor-coupler and drillpipe-couplerconnectors 820 and 905 is shown schematically in section view in FIG.10. The drillpipe-coupler connector 820 includes two conductive plugs1005 and 1010, which will protrude from the drillpipe 140 at the base ofthe sensor-module receptacle 310. The complementary sensor-couplerconnector 905 includes two conductive rings 1015 and 1020. Thisarrangement allows the connectors 820 and 905 to mate when, for example,the pressure sensor 175 is screwed into the sensor-module receptacle310. In such a configuration, the drillpipe coupler 315 and the sensorcoupler 810 have a direct electrical connection and the drillpipecoupler may be in direct electrical contact with the communicationsmedium 205.

Another example complementary pair of sensor-coupler anddrillpipe-coupler connectors 820 and 905 is shown in FIG. 11. Thesensor-coupler connector 820 includes an antenna 1105 and thedrillpipe-coupler connector includes an antenna 1110. In such aconfiguration, the sensor coupler transmits the signal indicative of theone or more measured properties to the drillpipe coupler using wirelesssignaling. For example, the sensor and drillpipe coupler may communicateusing short-hop telemetry or another wireless communication method. Eachof the antennas 1105 and 1110 may be any antenna or other transducercapable of providing communication between the sensor coupler 810 andthe drillpipe coupler 315.

In another example system, the sensor-coupler connector 820 and thedrillpipe-coupler connector 905 may include inductors or coils. Thesensor coupler 815 may pass current though its inductor to create anelectromagnetic field indicative of the sensor signal. Theelectromagnetic field, in turn, induces a current in the drillpipecoupler's inductor. In another example system, the connectors 820 and905 may form two plates of a capacitor allowing a signal to becapacitively induced on the opposing plate. The pressure sensor 175 orthe base of the sensor-module receptacle 310 may include a coating orinsert to provide a dielectric between the connectors 820 and 905 forcapacitive coupling.

Returning to FIG. 8, the components in pressure sensor 175 may requirepower to operate. In one example system, the necessary power may beprovided by power source 825, which may be a battery, such as a lithiumbattery. In another example system, the necessary power may be suppliedover the communication medium 205 using, for example, Power OverEthernet (POE). In yet another example system, a separate power line maybe run though the drillpipe 205 and taps may be provided for theattached pressure sensors 175. One or more pressure sensors 175 may bepowered from a central bus with power provided from the surface, or froma downhole central battery module. The power may be generated by, forexample, a downhole generator driven by the mud flow or drillpiperotation, or another power source.

An example system for detecting downhole conditions based on one or morepressure measurements from one or more pressure sensors 175 is shown inFIG. 12. The processor 180 determines a set of expected pressure values(block 1205). The processor 180 receives one or more pressuremeasurements from the pressure sensors 175 (block 1210). The processor180 may create a measured-pressure set from the pressure measurementsreceived and may determine one or more measured-pressure gradients(blocks 1215 and 1220). The processor 180 may compare the measuredpressure profile with the expected pressure profile (block 1225) todetect a downhole condition. If the processor detects a downholecondition (block 1230, which is shown in greater detail in FIG. 16), itmay identify, locate, and characterize the downhole condition (block1235, which is shown in greater detail in FIG. 17). The processor 180may perform further actions (block 1240). Regardless of whether theprocessor 180 detects a downhole condition (block 1230), it may modifythe expected-pressure set (block 1245) and may return to block 1210.

Creating the set of expected pressure values (block 1205) may includereceiving one or more expected pressures from an external source (e.g.,a user, a database, or another processor). Creating theexpected-pressure set may include accessing simulation results such asmodeling results. The modeling to create the expected pressure valuesmay include hydraulics modeling. The hydraulics modeling may considerone or more of the following: properties of the borehole anddrillstring, fluid properties, previous pressure measurements from theborehole or another borehole, or other measurements. In someimplementations an expected-pressure set may be created by copying oneor more values from a measured-pressure set. In other implementations anexpected-pressure set may be created by using values from ameasured-pressure set and adjusting or operating upon the values inaccordance with an algorithm or model. Some implementations utilizingmeasured-pressure sets in the creation of expected-pressure sets may usemeasured-pressure sets from a recent time window, an earlier timewindow, or multiple time windows. Certain example expected-pressure setsmay be derived from trend analysis of measured-pressure sets, suchtrends being observed or calculated in reference to for example elapsedtime, circulation time, drilling time, depth, another variable, orcombinations of variables.

The set of expected pressure values may include one or more pressurevalues at one or more depths in the borehole 165. The depths may belocations of interest within the borehole 165. A set of expected valuesmay be provided or determined corresponding to all or a portion of thefluid flow path within the borehole 165. The set of expected pressurevalues may represent one or more pressure profiles. A pressure profilemay include a set of two or more pressures, and a set of two or moredepths, or ranges of depths, where each pressure corresponds to a depthor a range of depths. The pressure profiles may exist, may bemeasurable, and may be modelable along the continuum of fluid or fluidsin the borehole 165 along one or more fluid flow paths within theborehole 165 and along one or more drillstring/borehole 165 hydraulicpaths or circuits.

Example pressure profiles may include one or more hydrostatic profiles.Other example pressure profiles include one or more static pressureprofiles that may include losses. The losses may include frictionallosses or major losses. Other example pressure profiles may includestagnation pressure profiles. The stagnation pressure profiles may berelated to flow velocity. Example pressure profiles may includearithmetic or other combinations or superposition of profiles.

While drilling the borehole 165, the processor 180 may change theexpected-pressure set to reflect changes in the well. The processor 180may change the expected-pressure set to reflect drilling progress (e.g.increasing depth). The processor 180 may alter the expected-pressure setto account for one or more known or unknown drilling process events orconditions. Changes to the pressure profile may be consistent orinconsistent with modeling, forecasts, or experience.

The processor 180 may model or be provided hydrostatic pressures,hydrostatic profiles, and changes in hydrostatic pressure within thedrillstring or the borehole 165. The processor 180 may model or beprovided frictional pressures, frictional profiles, frictional losses,or frictional changes within the drillstring or the borehole 165. Theprocessor 180 may model or be provided with one or more stagnationpressures, stagnation pressure profiles, stagnation pressure losses, orstagnation pressure changes within the drillstring or the borehole 165.The processor 180 may consider one or more factors impacting pressureincluding the dimensions of the drillstring (e.g., inner and outerdiameters of joints or other portions of the drillpipe and otherdrillstring elements) and dimensions of the borehole 165. The processor180 may also consider one or more depths corresponding to one or moremeasured pressures within the borehole 165. The processor 180 mayconsider drilling fluid properties (e.g., flow rates, densities), one ormore major loss sources (e.g., drill bit nozzles or mud motors), andwhether one or more portions of the borehole 165 are cased or open hole.

The processor 180 may be provided with or calculate one or more depthswhen calculating the expected-pressure set. The depths may include oneor more of the following: the true-vertical depth (TVD) (i.e., only thevertical component of the depth), measured depth (MD) (i.e., thedirection-less distance from the start of the borehole or otherreference point chosen such as ground level, sea level, or rig level, tothe bottom of the borehole or other point of interest along theborehole), and the round-trip depth (RTD). In general, the RTD is thedirection-less distance traveled by the drilling fluid. The RTD may bemeasured from the mud pumps or the start of borehole 165 (or anotherstarting reference point) to the end of the drillstring (e.g. the bit160) and back to a return reference point. The return reference pointmay be the start of the borehole 165, the point where fluid in thereturn line reaches atmospheric pressure, or another point. The end ofthe drillstring may or may not correspond to the bottom of the borehole165. The processor 180 may be provided with or determine the TVD of theborehole 165 to determine the hydrostatic changes in pressure. Theprocessor 180 may be provided with or calculate the measured depth (MD)of the borehole 165 to determine frictional and other pressure changes.

An example borehole 1300 that may be modeled by the processor 180 isshown schematically in FIG. 13. The borehole 1300 includes a verticalsegment 1305, a “tangent section” segment 1310 disposed to the verticalportion 1305 at angle 1315, and a horizontal segment 1320. A borehole1300 with a cased vertical segment 1305 of 3000 feet, an uncased segment1310 of 3000 feet, an angle 1315 of 60 degrees, and an uncasedhorizontal segment 1320 of 2000 feet will serve as the basis of upcomingexamples. This example borehole description is simplistic, butdemonstrative for purposes of discussing examples of the system. Actualboreholes may include other geometric features including curve sections.The curve sections may form transitions between straight segments or thecurve sections may take the place of one or more straight segments.Other example boreholes may include complex well paths. Other boreholefeatures may be considered when modeling the borehole 165. Such featuresmay include inner and outer pipe diameters, hole diameters, formationtypes, and bit geometry.

An example expected-pressure set based on borehole 1300 havingdimensions described above is shown in FIG. 14. The lines shown in FIG.5 may represent underlying data points (e.g., pressure-versus-depth).This example expected-pressure set assumes a constant flow rate andconstant drilling fluid density though the entire round-trip distance,although such constancy is not always the case in practice and is not alimitation. The expected-pressure set shows static pressure, includinghydrostatic pressure versus the percentage of round-trip distance.Standpipe pressure 1400 is the pressure within the drillstring at zerodepth. Pressure segment 1405 represents the pressures in the drillstringthrough the vertical borehole segment 1305. Pressure segment 1410represents pressures within the drillstring through the 60 degreeborehole segment 1310. Pressure segment 1415 represents pressures withinthe drillstring through the horizontal borehole segment 1320. Pressuresegment 1420 represents pressures through BHA elements. In this example,the BHA elements include MWD/LWD tools 150, a rotary steerable tool, anddrill bit 160. Pressure segment 1425 represents the annular pressure(i.e., the pressure outside the drillstring) through the horizontalborehole segment 1320. Pressure segment 1430 represents the annularpressure though borehole segment 1310. Pressure segment 1435 representsthe annular pressure through the borehole segment 1305.

Each of pressure segments in an expected-pressure set may change basedon the configuration of the drillstring. For example, the drillstringmay include one or more subs 155 or MWD/LWD tools 150 that may causeinternal flow restriction relative to the drillpipe 140. In such asituation, the expected pressure profile may consider the subs 155 andthe MWD/LWD tools 150 and their location along the drillstring (e.g.,within different borehole segments) when determining theexpected-pressure set. The processor 180 may alter the expected-pressureset to account for pressure changes caused by subs 155 or the MWD/LWDtools 150 in the pressure segment where the subs 155 or the MWD/LWDtools 150 are located. The expected-pressure profile may also accountfor resulting pressure changes to the segments upstream of the subs 155and the MWD/LWD tools 150. The expected-pressure set may reflectgradient and pressure loss relationships.

Another example expected-pressure set based on borehole 1300 withdimensions described above is shown in FIG. 15. The exampleexpected-pressure set also assumes a constant flow rate and constantdrilling fluid density though the entire round-trip depth. Theexpected-pressure set shows static pressure, excluding hydrostaticpressure, which may be modeled and subtracted out, versus the percentageof round-trip distance. Standpipe pressure 1500 represents the pressureat zero depth. Pressure segment 1505 represents pressures within thedrillstring though borehole segments 1305, 1310, and 1320. Pressuresegment 1510 represents pressures through MWD/LWD tools 150, a rotarysteerable tool, and drill bit 160. Pressure segment 1515 representsannular pressure through borehole segments 1305, 1310, and 1320.

Returning to FIG. 12 and referring to system elements shown in FIG. 1,once the drillstring has entered to the borehole 165, the processor 180receives pressure measurements from one or more pressure sensors 175(block 1210). The processor 180 creates a measured-pressure set (block1215). The processor 180 may determine one or more measured-pressuregradients (i.e., the change in measured pressure-versus-depth). Certainexample implementations include at least three pressure sensors 175 toprovide at least two pressure gradients. Certain example implementationsinclude at least one pressure gradient corresponding to each of at leasttwo sections of the flow path or borehole, such sections corresponding,for example, to: (a) ranges of hole angle (e.g. vertical, curve,tangent, horizontal sections); (b) lengths of common averagecross-sectional flow area (e.g. over collars, over heavyweight pipe,over drillpipe, in different casing diameters or hole diameters); (d)lengths of borehole exposure to one or more particular formation types;or (d) cased versus open hole.

In certain example implementations, the processor may not determine theone or more gradients (block 1220). For example, if the processor 180 isdetecting at least one downhole condition which can be detected byobserving absolute differences between one or more measured pressures,or between one or more measured pressures and one or more expectedpressures, it may not determine the one or more gradients.

The number and location of the pressure sensors 175 may affect thenumber of pressure-versus-depth data points available in themeasured-pressure set. Additionally, any pressure sensor 175 that ismoved from one location to another (e.g. during drilling or tripping)may provide multiple data points in a measured-pressure set.

At least two pressure-versus-depth data points may be used to determinea measured-pressure gradient. Where actual pressure-versus-depth datapoints are not available, the processor 180 may estimate one or morepressure-versus-depth data points. The processor 180 may estimatepressure-versus-depth data points by interpolating between data points,extrapolating gradients, or determining transitions between gradients.

In certain example system, the measured-value set of pressures, theexpected-value set of pressures, or both may be displayed to theoperator using the terminal 185. For example, the measured-value set ofpressures may be juxtaposed to the expected-value set of pressured usingthe terminal 185, allowing the user to manually detect, identify,characterize, or locate a downhole condition. The measured-value setsand the expected-value sets may be presented to the user in a graphicalformat (e.g., a chart, log, plot, or series of plots) or in a textualformat (e.g., a table of values). Certain example systems may includepresenting an evolution of one or more of the measured-value sets ofpressures and the expected-value sets of pressures to the user. Forexample, the system may display a series of plots to the user todemonstrate the evolution of one or more of the measured-value sets ofpressures and the expected-value sets of pressures. The system maydisplay an evolution of both the measured-value set of pressures and theexpected-value set of pressures. Certain evolutions may be evolutionsover time, depth, or other variables or combinations of variables.

Individual measured pressures in the measured-pressure set may bemeasured in a short time window (e.g. seconds) for minimized delay indetecting of conditions. In many implementations individual measuredpressures in the measured-pressure set may be measured substantiallysimultaneously. As used herein, “substantially simultaneously” meansonly that the measurements are taken in the same time period duringwhich conditions are not expected to change significantly, in thecontext of the particular operational process. For example, duringdrilling or in-slips, and during constant flow periods (i.e., eitherwhen the pumps are on and steady or when they are off), ameasured-pressure set may include relevant pressure characteristicsbetween the individual depths, even if the individual pressures areobtained tens of seconds or even minutes apart. Many downhole conditions(e.g., cuttings build-up) may be detected using measured-pressure sets,the values of which are obtained in a time window of minutes. Duringtransient operational processes such as tripping or transitioning flowrate, and for detection of events or conditions which have a faster timeconstant (e.g. gas influx), a shorter time window for collecting andanalyzing a measured-pressure set may be preferred.

Individual measured pressures in the measured-pressure set may bemeasured sequentially. In some example implementations, the sequence bywhich the pressures are measured may be controllable by, for example,the processor 180. For example, the sequence by which the pressure aremeasured may be determined by an algorithm based on drilling conditionsor other factors.

Example systems may provide measured versus expected pressures,profiles, or gradients in different operational processes of wellconstruction, including, for example and without limitation: on-bottomrotary drilling, sliding, tripping, off-bottom circulating for holecleaning, circulating up a kick, circulating pills or transitioning mudtypes, and leak-off testing.

An example system for determining if there is a downhole condition(block 1230) is shown in FIG. 16. In general, a downhole condition mayinclude any regular or irregular, static or dynamic, condition or eventalong a round-trip fluid path. Example downhole conditions may include,but are not limited to, one or more of the following: a flowrestriction, a cuttings build-up, a wash-out, or an influx. Theprocessor 180 may determine if the measured standpipe pressure is out ofrange (block 1605), if one or more measured-pressure gradients are outof range (block 1615), if another measured pressure is out of range(block 1620), if a measured bottom hole equivalent circulating density(ECD) is out of range (block 1625), or if other measurements are out ofrange (block 1630). If none of these quantities are out of range theprocessor returns “N” (block 1635), otherwise it returns “Y” (block1610).

The processor 180 may determine whether any of the quantities are out ofrange (blocks 1605-1630) by determining if the difference between themeasured property (e.g., measured static pressure or static pressuregradient) and the expected property (e.g., expected static pressure orstatic pressure gradient) is greater than a maximum delta for theproperty.

In certain implementations, the maximum delta may be determinedautomatically by the processor 180. In other implementations the maximumdelta may be input by an operator. In other implementations, the maximumdelta may be obtained from a separate processor or model. In certainimplementations, the maximum delta may be determined by an operator oran independent model based on one or more measured pressures.

The maximum delta determination may be based on an absolute differenceversus an expected value, or it may be based on a percentage deviationfrom the expected value. The maximum delta may be based upon a function.For example, the maximum delta may increase or decrease with depth. Themaximum delta may vary over a depth range or over an operational phase.For example, the maximum delta may be adjusted for a certain depthinterval due to narrow pore pressure-fracture gradient window. Themaximum delta determination may also be dependant on time. In certainimplementations, a difference between a measured pressure and anexpected pressure exceeding the maximum delta may be not be acted onunless it persists for a particular duration or longer.

Returning to FIG. 12, if the processor 180 determines that there is nota downhole condition (block 1230) it may modify the expected-pressureset (block 1245) and return to block 1205. In certain implementations,the processor may not execute block 1245 without operator input (e.g.,review, approval, input, or intervention). In other implementations,block 1245 may be executed without operator intervention. In one examplesystem, the processor 180 modifies the expected-pressure set based onmore or more parameters or parameter sets (e.g. actual pressuregradients) observed or measured downhole. Such an update may provideaccounting in the new expected-pressure set for new or updated fluid orflow path circumstances (e.g. increased hole depth, changed fluiddensity, changed rate of penetration and/or cuttings removal) but whichare not deemed downhole conditions (block 1230).

If the processor 180 determines that there is a downhole condition(block 1230), it may identify the condition (e.g. determine the typecondition detected), it may characterize the downhole condition (e.g.determine the magnitude or other properties of the downhole condition),and it may locate the position of the downhole condition (e.g. determinethe depth or depth interval of the detected condition) (block 1235), andit may take additional actions (block 1240).

An example system for identifying, locating, and characterizing at leastone downhole condition (block 1235) is shown in FIG. 17. The processor180 may determine if the measured standpipe pressure, measured bottomhole annular pressure (sometimes expressed as equivalent circulatingdensity (ECD)), or other measured drillpipe or annulus pressures areincreased or decreased relative to the expected values (block 1705). Ifthe measured pressures are decreased relative the expected values, theprocessor 180 may identify and locate one or more of the followingdownhole conditions: a pipe wash-out (block 1710) or a lost circulationzone (block 1715). If, however, the measured pressures are increasedrelative to the expected values, the processor 180 may identify andlocate one or more of the following downhole conditions: an annulusobstruction (e.g., cuttings build-up) (block 1720), a liquid influx(block 1725), or excessive cutting suspended in the annulus (block1730). In certain example systems, the processor 180 may perform one ormore of identifying, locating, or characterizing the at least onedownhole condition. The processor 180 may identify and locate one ormore other downhole conditions (block 1735). The processor 180 maycharacterize the at least one downhole condition (block 840). Thesedownhole conditions may be characterized by increasing or decreasingpressures, or other characteristics, which the system may identify,characterize, or locate. The processor may return one or more of theidentification, location, and characteristics of detected downholeconditions (block 1745).

An example system for identifying and locating a pipe wash-out (block1710) is shown in FIG. 18. In a wash-out condition the full flow rateupstream of the wash-out may be divided at the wash-out location, with aportion continuing along the intended drillstring path to the bit 160and back to surface through the annulus, while a portion of the fluidtakes a “short circuit” path directly to the annulus and back tosurface. Pressures and pressure gradients may change accordingly fromthe expected (e.g., non-wash-out) values. For example, a frictional losspressure gradient within the drillstring may be decreased downstream ofthe wash-out location. The processor 180 may determine if there is apressure gradient decrease (e.g., measured-pressure gradient is lessthan expected-pressure gradient) in a depth interval (block 1805) and,if not, may return nothing (block 1810). Otherwise, the processor 180may determine if there is a pressure loss (e.g., measured pressure isless than expected pressure) in an interval and, if not, may returnnothing (block 1810). Otherwise, the processor 180 may return “PIPEWASH-OUT” as an identification of the likely downhole condition (block1820). The processor 180 may return the likely location of the downholecondition as upstream of the first measured-pressure gradient reductionrelative to the expected-pressure gradient (block 1825). The additionalactions in response to the wash-out condition (FIG. 12, block 1240) mayinclude rapidly tripping pipe out of hole to the location of the likelywash-out condition, without a requirement to inspect every connectionduring the tripping process for possible wash-out.

An example measured-value set (1910) and expected-value set (1905)demonstrating a possible pipe wash-out condition is shown in FIGS.19-21. FIG. 19 shows pressure (including hydrostatic pressure) versusround-trip distance representations of the sets. The expected-value setin FIGS. 20-21 is represented by plot 2005, while the measured-value setis represented by plot 2010. FIGS. 20-21 show pressure (excludinghydrostatic pressure) versus round-trip distance representations of thesets. FIG. 21 is scaled to the area of interest. The inflection point2105 represents the location of the pipe wash-out.

Using the data shown in FIGS. 19-21, the processor 180 may observe thedecrease in the measured-pressure gradient as compared to theexpected-pressure gradient, which is particularly evident in FIGS. 20and 21 (block 1805). The processor 180 may also observe the measuredpressure drop over an interval, which is evident in all three figures(block 1810). Based on these observations, the processor may identifythe condition as a pipe wash-out. The processor 180 may also observewhere the measured pressured gradient begins to decrease to determinethat the location of the condition is upstream of or at the depth atinflection point 2105 in FIG. 21. FIG. 21 includes a broken line todemonstrate the change in the measured-pressure gradient at theinflection point 2105. The processor 180 may locate the pipe wash-out atthe location upstream of or at the inflection point 2105 (block 1825).

An example system for identifying and locating lost circulation (e.g.,fluid escaping into the formation) (block 1715) is shown in FIG. 22. Ina lost circulation condition a total flow rate from upstream of the lostcirculation location or zone along the annulus return path may bedivided, with all or a portion of the circulation being lost to theformation and the remainder continuing downstream along the intendedreturn path to surface. Pressures and pressure gradients may changeaccordingly from the expected (e.g., non-lost circulation condition).For example, a frictional loss pressure gradient may be reduceddownstream of a lost circulation zone. The processor 180 may determineif there is a measured-pressure gradient in the annulus that isdecreased from a point to the surface (block 2205) and, if so, theprocessor 180 may return “LOST CIRCULATION” as a likely identificationof the downhole condition (block 2215) and may return a location at orupstream of the first measured gradient reduction as the location of thecondition (block 2220). Otherwise, the processor 180 may return nothing(block 2210).

An example measured-value set (2305) and expected-value set (2310)demonstrating a likely lost-circulation condition is shown in FIGS. 23and 24. FIGS. 23 and 24 show a pressure (including hydrostatic pressure)versus round-trip distance representations of the sets. FIG. 24 isscaled to show the location of the inflection point in themeasured-pressure gradient.

Using the data shown in FIGS. 23 and 24, the processor 180 may observe ameasured-pressure gradient decrease at inflection point 2405 in FIG. 24(block 2205). In FIG. 24, the change in gradient is highlighted by thebroken line. Based on this observation, the processor 180 may identifythe condition as a lost circulation zone (block 2215) and locate thecondition at or upstream of the inflection point 2405 (block 2220).

An example system for identifying and locating a likely annulusobstruction (block 1720) is shown in FIG. 25. An annulus obstructioncondition may be due to cuttings build-up, swelling shale, or othercondition restricting flow over an interval. The processor 180 maydetermine if there is a measured-pressure gradient increase over aninterval (block 2505) and if there is an increased measured pressureupstream of the gradient increase (block 2515). If either of these arenot true the processor 180 may return nothing (block 2510). Otherwise,the processor 180 may return “ANNULUS OBSTRUCTION” as a likelyidentification of the downhole condition (block 2520) and may return thedepth range corresponding to the range of increased measured-pressuregradient as the likely location of the condition (block 2525).

An example measured-value set (2605) and expected-value set (2610)demonstrating an annulus obstruction condition is shown in FIG. 26. FIG.26 shows a pressure (including hydrostatic pressure) versus round-tripdistance representations of the sets.

Using the data shown in FIG. 26, the processor 180 may observe anincrease in the measured-pressure gradient over an interval 2615 (block2505) and increased measured pressure upstream of the interval 2615(block 2515). The expected-pressure gradient is shown by a broken linein the figure. Based on these observation, the processor 180 mayidentify the particular condition as an annulus obstruction (block 2520)and may locate the condition at the range of increased measured-pressuregradients (block 2525).

An example system for identifying and locating a fluid influx into thedrillstring (block 1725) is shown in FIG. 27. Note for purposes herein“fluid influx” means a liquid fluid influx such as a water or oil; gasinflux conditions may be a special case considered separately andidentified as such. A fluid influx condition may be characterized by atotal flow rate from upstream of the influx location or zone along theannulus return path supplemented by additional flow coming into theborehole 165 from the formation. The fluid influx condition may furtherbe characterized by an increased flow rate therefore continuingdownstream along the intended return path to surface. Pressures andpressure gradients may change accordingly from the expected (e.g.,non-influx condition). For example, a frictional loss pressure gradientmay be increased downstream of the influx zone. The processor 180 maydetermine if there is an increased measured-pressure gradient in theannulus from a point downstream to the surface (block 2705). If so, theprocessor 180 may return “FLUID INFLUX” as a likely identification ofthe downhole condition (block 2715) and may return a location at orupstream of the first (i.e., upstream-most) measured-pressure gradientincrease as the likely location of the downhole condition (block 2720).

An example measured-value set (2805) and expected-value set (2810)demonstrating a fluid influx condition is shown in FIGS. 28 and 29.FIGS. 28 and 29 show pressure (including hydrostatic pressure) versusround-trip distance representations of the sets. FIG. 29 is scaled toshow the location of the inflection point in the measured-pressuregradient.

Using the data shown in FIGS. 28 and 29 the processor 180 may observe anincreased measured-pressure gradient in the annulus starting frominflection point 2905 (FIG. 29) and downstream to the surface. Based onthis observation, the processor 180 may identify the particularcondition as a fluid influx into the drillstring (block 2715) and maylocate the condition at or upstream of the first measured-pressuregradient increase (block 2720).

An example system for identifying and locating a cutting build-up (block1730) is shown in FIG. 30. A cuttings build-up may be identified as anannulus obstruction over an interval. Further analysis may morespecifically indicate that the obstruction is likely to be a cuttingsbuild-up. The processor 180 may determine if there is an increasedpressure gradient over an interval (block 3005). If so, and if theinterval is in a particular borehole section known to be susceptible tocuttings build-up, such as the “knee” section in the annulus (i.e.,where the horizontal section transitions to the 60 degree section)(block 3010), the processor 180 may return “CUTTING BUILD-UP” as thelikely identification of the downhole condition (block 3015) and mayreturn a likely range of the increased measured gradient as the locationof the condition (block 3020). Otherwise, the processor 180 may returnnothing (block 3025).

An example measured-value set (3105) and expected-value set (3110)demonstrating the cutting build-up condition is shown in FIGS. 31 and32. FIGS. 31 and 32 show a pressure (including hydrostatic pressure)versus round-trip distance representations of the sets. FIG. 32 isscaled to show the location of the range of increased measured-pressuregradients.

Using the data shown in FIGS. 31 and 32 the processor 180 may observeincreased pressure gradients over an interval 3205 (FIG. 32) (block3005) and determine that the interval is in the knee between theborehole sections 1310 and 1320 (block 3010). Based on theseobservations, the processor 180 may identify the condition as a likelycutting build up in the annulus (block 3020) and locate the condition atthe range of increase measured-pressure gradients (block 3025).

In certain implementations, one or more pressure sensors 175 may measureannulus static pressures and based on these pressure measurements, theprocessor 180 may determine that the increase pressure gradient in theinterval 3205 reflects increased frictional losses over the interval,which may reflect the increased annular flow velocity and likelycuttings build up. In other implementations, which are not representedin FIGS. 22 and 23, one or more pressure sensors 175 may directlymeasure stagnation pressure. In such implementations, the processor 180may determine flow velocities from the stagnations pressuremeasurements. The processor 180 may determine the flow velocities byrelating the stagnation pressure to the square of the fluid velocity.

Returning to FIG. 17, the processor 180 may identify one or more otherdownhole conditions (block 1735). An example system for determining oneor more other downhole condition is shown in FIG. 33. The processor 180may identify and may locate the depth where the drilling fluid changesphase (e.g., liquid to gas), or inverts from a liquid to gas continuousphase (block 3305). Such example system may be useful for underbalanceddrilling systems. The processor 180 may also detect and may locate a gasinflux in the annulus (block 3310). A gas influx may result in pressureand gradient changes along the annulus versus the expected-pressure setwhich while more complex than the case of a liquid influx are stillmodelable by known methods. The processor 180 may also detect and maylocate other conditions that have an effect on downhole pressures (block3315).

Although the identification and location of downhole conditions has beendiscussed with respect to normal flow, the system may also identifydownhole conditions when operating with reversed flow (e.g. drillingfluid is pumped down the annulus and flows up the drillstring). Theprocessor 180 may detect simultaneous downhole conditions. The processor180 may separate the pressure indicia of the plurality of downholeconditions using analytical methods. The processor 180 may receivemeasurements from sources other than pressures sensors mounted to thedrillstring to detect at least one downhole condition. For example, theprocessor 180 may monitor operational data such as the standpipepressure, rate of penetration, rotary RPM, “in-slips” sensors,hook-load, and the flow rate and other parameters of the drilling fluid,both inbound and outbound.

The downhole conditions may also be characterized by the processor 180(block 1740). Such characterization may include the determination of alikely magnitude range of the condition. The magnitudes of the measuredand expected pressure values and measured and expected-pressuregradients may be indicative (analytically through known hydraulicsrelationships and/or empirically) of the characteristics of thecondition. For example, the particular changes in pressures or gradientsmay be used to estimate particular percentage of flow bypassing in awash-out, particular flow rate of a fluid influx, particular lost-flowrate of a lost circulation zone, or particular percentage crosssectional area of an obstruction or a cuttings bedded interval.

The processor 180 may perform additional actions after detecting adownhole condition (block 1240). As shown in FIG. 34, the additionalactions may include one or more of the following: sending an alarm(block 3405), offering advice on actions to the operator (e.g. shut-inthe borehole, change fluid density, change flow rate, change rotaryspeed, short trip e.g. for hole cleaning) (block 3410), or sending acontrol signal to surface or downhole rig equipment or tools responsiveto the condition (block 3415). As shown in FIG. 35, for example, thecontrol signal may cause the surface or downhole rig equipment to tripto the location of a problem joint (block 3505). The control signal mayadditionally or alternatively cause other automated actions. Theseactions may include, for example: shutting-in the borehole, changingfluid density, changing flow rate, changing rotary speed, or shorttripping.

The processor 180 may also modify the expected-pressure set (block1245), as shown in FIG. 36. The processor 180 may modify theexpected-pressure set to account for a detected downhole condition(block 3605). The processor 180 may modify the expected-pressure set toaccount for other factors, such as those discussed with respect todetermining the expected pressure set (block 1205).

The present invention is therefore well-adapted to carry out the objectsand attain the ends mentioned, as well as those that are inherenttherein. While the invention has been depicted, described and is definedby references to examples of the invention, such a reference does notimply a limitation on the invention, and no such limitation is to beinferred. The invention is capable of considerable modification,alteration and equivalents in form and function, as will occur to thoseordinarily skilled in the art having the benefit of this disclosure. Thedepicted and described examples are not exhaustive of the invention.Consequently, the invention is intended to be limited only by the spiritand scope of the appended claims, giving full cognizance to equivalentsin all respects.

1-20. (canceled)
 21. An automated drilling system for drillinghydrocarbon wells, comprising: a derrick, a draw works, and at least oneof a rotary table and top drive; a drill string; a plurality of pressuresensors to measure pressures at the drillstring, wherein the drillstringcomprises drillpipe, and wherein at least one pressure sensor is on orwithin the drillpipe; and a processor and memory, the memory includingnon-transitory executable instructions that, when executed, cause theprocessor to: collect a set of measured pressures from one or more ofthe plurality of pressure sensors; analyze the set of measured pressuresfrom one or more of the plurality of pressure sensors; provide an outputthat is a function of the set of measured pressures; and use the outputin a drilling process; wherein at least one of the pressure sensors iscoupled to the processor.
 22. The automated drilling system of claim 21,further comprising: a mud pump; and one or more of a drilling fluidsupply line, a standpipe, a kelly hose, and a drilling fluid returnline.
 23. The automated drilling system of claim 22, further comprising:a second pressure sensor to measure pressures at one or more of thedrilling fluid supply line, the standpipe, the kelly hose and thedrilling fluid return line.
 24. An automated drilling system fordrilling hydrocarbon wells, comprising: a drill string; a plurality ofpressure sensors to measure pressures at the drillstring, wherein thedrillstring comprises drillpipe, and wherein at least one pressuresensor is on or within the drillpipe; and a processor and memory, thememory including non-transitory executable instructions that, whenexecuted, cause the processor to: collect a set of measured pressuresfrom one or more of the plurality of pressure sensors; analyze the setof measured pressures from one or more of the plurality of pressuresensors; provide an output that is a function of the set of measuredpressures; and use the output in a drilling process; wherein at leastone of the pressure sensors is coupled to the processor.
 25. Theautomated drilling system of claim 24, wherein the executableinstructions that, when executed, further cause the processor to:analyze the set of measured pressures from one or more of the pluralityof pressure sensors with a set of expected pressures; and provide anoutput that is a function of the set of measured pressures and the setof expected pressures.
 26. The automated drilling system of claim 25,wherein the executable instructions that cause the processor to collecta set of measured pressures from one or more of the plurality ofpressure sensors and analyze the set of measured pressures with a set ofexpected pressures are executed in real-time.
 27. The automated drillingsystem of claim 25, wherein the set of expected pressures are from anexternal source, wherein the external source is one or more of a user, adatabase, or another processor.
 28. The automated drilling system ofclaim 25, wherein the set of expected pressures are created based onhydraulics modeling.
 29. The automated drilling system of claim 24,where the executable instructions further cause the processor to: detecta downhole condition; and send a control signal to surface or downholerig equipment or tools responsive to the downhole condition, wherein thecontrol signal causes an automated action.
 30. The automated drillingsystem of claim 29, wherein the control signal causes shutting-in theborehole.
 31. The automated drilling system of claim 29, wherein thecontrol signal causes changing fluid density.
 32. The automated drillingsystem of claim 29, wherein the control signal causes changing a flowrate.
 33. The automated drilling system of claim 29, wherein the controlsignal causes changing rotary speed.
 34. The automated drilling systemof claim 29, wherein the control signal causes short tripping.
 35. Anautomated drilling method of collecting and analyzing one or morepressures, the automated drilling method implemented, at least in part,in a computer system comprising at least one processor, the methodcomprising: measuring pressures at a plurality of locations along adrillstring using a plurality of pressure sensors, the drillstringcomprising drillpipe, and wherein at least one pressure sensors is on orwithin the drillpipe; collecting a set of measured pressures from one ormore of the plurality of pressure sensors; analyzing the set of measuredpressures from one or more of the plurality of pressure sensors;providing an output that is a function of the measured pressures; andusing the output in a drilling process.
 36. The automated drillingmethod of claim 35, further comprising: analyzing the set of measuredpressures from one or more of the plurality of pressure sensors with aset of expected pressures; and providing an output that is a function ofthe measured pressures and expected pressures.
 37. The automateddrilling method of claim 36, wherein the collecting the set of measuredpressures from one or more of the plurality of pressure sensors and theanalyzing the set of measured pressures from one or more of theplurality of pressure sensors with the set of expected pressures areperformed in real time.
 38. The automated drilling method of claim 36,wherein the set of expected pressures are from an external source. 39.The automated drilling method of claim 38, wherein the external sourceis one more of a user, a database, and another processor.
 40. Theautomated drilling method of claim 36, wherein the expected pressuresare created based on modeling.
 41. The automated drilling method ofclaim 40, wherein the modeling is hydraulics modeling.
 42. The automateddrilling method of claim 36, wherein the expected pressures are createdbased on copying one or more values from the set of measured pressures.43. The automated drilling method of claim 36, wherein the expectedpressures are created based on trend analysis of measured pressures fromone or more of the plurality of pressure sensors.
 44. The automateddrilling method of claim 35, further comprising: detecting a downholecondition; and sending a control signal to surface or downhole rigequipment or tools responsive to the downhole condition.
 45. Theautomated drilling method of claim 44, wherein the control signal causesshutting-in the borehole.
 46. The automated drilling method of claim 44,wherein the control signal causes changing fluid density.
 47. Theautomated drilling method of claim 44, wherein the control signal causeschanging a flow rate.
 48. The automated drilling method of claim 44,wherein the control signal causes changing rotary speed.
 49. Theautomated drilling method of claim 44, wherein the control signal causesshort tripping.